Process for reducing the production of water in oil wells

ABSTRACT

A process is described for reducing the production of water in oil wells, with temperatures of up to (90° C.), which comprises the injection in the formation around the well of an aqueous solution of one or more polymers selected from those having general formula (I) wherein: n ranges from (0.40) to (0.70), preferably from (0.5) to (0.65); m ranges from (0.15) to (0.65), preferably from (0.3) to (0.5); p ranges from (0.02) to (0.20), preferably from (0.05) to (0.10); n+m+p=1; x 1  is selected from H and CH 3 ; R 1 , R 2  the same or different, are selected from C 1 –C 10  monofunctional hydrocarbyl groups

The present invention relates to a process for reducing the productionof water in oil wells, with temperatures of up to 90° C., whichcomprises the injection into the formation of an aqueous solution of acationic polymer.

The coproduction of water is a fact which concerns, to varying extentsand with different times, all oil or gas wells, and which can havestrong negative economic repercussions. The excessive production ofwater in fact causes both an increase in the costs relating to thedisposal of the water and also to a reduction in income due to thelimited productivity of hydrocarbons.

In gas fields, moreover, a high water-cut (i.e. the ratio between thewater flow-rate of a well and the total water+hydrocarbon flow-rate) canlead to the flooding of the well and consequently its closure.

Furthermore, in the future, problems associated with the production ofwater will become even more important in view of the characteristics offields currently in production and of new exploration frontiers. Theproduction of existing fields in fact (increasingly more mature) isnormally characterized by a water-cut which increases with time. Theexploration frontiers moreover are moving towards offshore reservoirs,often in deep water, and in areas often characterized by severeenvironmental regulations.

In wells with a high water-cut, the problem can generally be solved bythe mechanical insulation of the production area or by recompletion orworkover. The latter solution however is extremely onerous and can causethe loss of enormous volumes of hydrocarbons present in the microlevelsstill not influenced by the arrival of water.

“Water shut-off” interventions with gelifying chemical systems (usuallypolyacrylamides cross-linked with Cr(III) or with systems based onsilicates), can represent a valid alternative to mechanical insulation;these compositions, injected into the formation, completely block themovement of the fluids in the zones treated. With this technique, it ispossible to totally reduce or eliminate the production of water ataccessible costs. This technology however only has a high probability ofsuccess when it is possible to identify and selectively insulate thewater production areas during the treatment, so as not to damageproduction from the layers still saturated with hydrocarbons.

Finally, the RPM (Relative Permeability Modifier) technology is based onthe injection, in all intervals open for production, of a chemical agentcapable of selectively reducing the permeability to water. The chemicalsystems used in this type of treatment are hydrosoluble polymers whichmodify the permeability of the formation following adsorption on therock surface. In this way, the permeability in the high water-cutintervals is selectively reduced, whereas the permeability of theintervals which produce hydrocarbons remains unaltered. Intervening withthis approach, when appropriate, has numerous advantages with respect tothe conventional technologies, in particular: (i) limit risk of damage,(ii) low environmental impact, (iii) low cost of the treatment thanks tointerventions of the “bullheading” type.

The condition necessary for effective treatment with a permeabilitymodifier polymer is that the polymer itself interacts with the rocksurface creating a layer capable of modifying the flow properties of theporous medium. The polymer must therefore have a particularly strongattractive interaction with the rock surface, in order to maximize theadsorption and stability of the layer of adsorbed polymer, over a periodof time.

The polymers used so far have various limitations which have delayed thediffusion of the RPM technology. In particular: polyacrylamides (PAM)have a poor efficacy and reduced duration of the treatment due to thelimited thermal stability; polyacrylamides modified by the introductionof cationic groups have a good efficacy but low resistance totemperature; biopolymers (such as scleroglucan) have injectivityproblems as a result of the high viscosity of the polymeric solution andits tendency to flocculate.

Experts in the field have consequently felt the necessity of findingpolymers capable of being more effectively adsorbed on rock matrixes andtherefore capable of selectively reducing the permeability to water andalso resistant to the temperature of the formation.

It has now been found that particular cationic polymers adequatelysatisfy the above demands, and are particularly thermally stable atmedium-high temperatures. Adsorption tests carried out on siliceous sandusing polymers containing cationic groups and analogous non-ionicpolymers have in fact demonstrated that the former are more stronglyadsorbed on the rock with respect to the latter, as a result of theattractive interaction between the surface of the negatively chargedsand and the positively charged polymer.

In accordance with this, the present invention relates to a process forreducing the production of water in oil wells which comprises theinjection into the formation around the well of an aqueous solution ofone or more polymers selected from those having general formula (I):

wherein

-   n ranges from 0.40 to 0.70, preferably from 0.5 to 0.65;-   m ranges from 0.15 to 0.65, preferably from 0.3 to 0.5;-   p ranges from 0.02 to 0.20, preferably from 0.05 to 0.10;-   n+m+p=1;-   X₁ is selected from H and CH₃;-   R₁, R₂, the same or different, are selected from C₁–C₁₀    monofunctional hydrocarbyl groups.

In the preferred embodiment, in the compound having general formula (I)the polymer has: n=0.65, m=0.3, p=0.05, X₁=H, R₁=CH₃, R₂=CH₃.

The molecular weight of the polymers usually ranges from 1.5 to 12million.

The aqueous solution which can be used in the process of the presentinvention contains a quantity of polymer of the compound having generalformula (I) preferably ranging from 300 to 10000 ppm, even morepreferably from 500 to 4000 ppm.

Any type of water available provided it has no suspended solids, can beused as carrying medium, as the compound having general formula (I) isneither influenced by the type or quantity of anions and cations usuallycontained in water.

The aqueous solution of the present invention normally has a viscosityranging from 1.5 to 10 cP, much lower values than those of the gelifyingsolutions.

The volume of aqueous solution to be injected into the formation dependson the height of the production formation to be treated and on the depthto which the solution must penetrate (invasion radius).

The flow-rate of the aqueous solution to be injected is selected inrelation to the type of formation to be treated. Furthermore the aqueoussolution to be injected can be fed into the formation at the desiredpressure, provided this is not higher than the fracture pressure. It isknown to experts in the field that it is advantageous for the solutionto be injected as rapidly as possible, compatibly with thecharacteristics of the formation, in order to reduce the treatment timeand consequently production stoppage, to the minimum.

When considered necessary, the process of the present invention can bepreceded by an optional pretreatment step (preflush) which can becarried out for example with an aqueous solution containing asurface-active agent, in order to clean the formation to be treated andobtain a more effective adsorption of the polymer.

In the preferred embodiment, the process of the present invention ispreferably followed by an overflush step, i.e. treatment of theformation with brine or gas or oil, in order to push the polymer intothe formation. The overflush with gas also has the purpose ofre-establishing the connectivity of the gas layer (in gas wells).

Finally, at the end of the injection of the aqueous solution of thecompound having general formula (I), a shut-in step is preferablyeffected, i.e. closure of the well to allow a more effective adsorptionof the polymer on the rock matrix.

The process of the present invention has many advantageous aspects, andin particular requires limited quantities of polymer having generalformula (I). Furthermore it has the unexpected advantage of beingapplicable to both gas and oil formations, with temperatures up to about90° C.

The following examples are provided for a better understanding of thepresent invention.

EXAMPLES

The polymer (called DP/PT 2130, produced by Floerger) used in theexamples has the following formula. This is a terpolymer (AM-NVP-DADMAC)obtained from the polymerization of three monomers:

-   acrylamide (AM), N-vinylpyrrolidone (NVP),    diallyldimethylammoniumchloride (DADMAC). The polymer has a    molecular weight equal to 5 million.

For comparative purposes, in the experimental part another cationicpolymer is also used, which is not a part of the invention. This is acationic polymer (MCAT, produced by MI Drilling Fluids), apoly{acrylamide-acrylamide-(methyltrimethylammonium)} copolymer. Thepolymer has a molecular weight equal to 2 million.

Both products are in the form of a white powder.

Chemical Structure of the Polymer DP/PT 2130 (n=0.65, m=0.30, p=0.05)

Chemical Structure of the Cationic Polymer MCAT (p=0.95, q=0.05) Example1 Performances of the Cationic Polymers DP/PT 2130 and MCAT

The performances of the polymers MCAT and DP/PT 2130 were evaluated bymeans of: a) Adsorption test on sand of the solutions; b) Thermalstability evaluation by means of NMR analysis; c) Core test

1a—Static Adsorption Test at a Temperature of 25° C.

The polymer solutions were prepared in brine (filtered and degassedsolution of KCl2%) at concentrations of 1000 or 2000 ppm. After puttinga certain quantity of sand (3–5 g) in contact with the polymericsolution in a hermetically sealed glass container, the solution with thesand is put under stirring at the desired temperature to favour contactbetween the polymer and surface of the sand. After about 24 hours at 25°C., the quantity of polymer adsorbed at the interface is determined bydifference (between that initially charged and that remaining in thesolution after the test) by means of TOC analysis (Total OrganicCarbon).

The tests were carried out using sand with a prevalently siliceous andclay composition. Table 1 shows a comparison between the adsorptionvalues of the polymer DP/PT 2130 and of the comparative polymer MCAT.

Table 1. Adsorption comparison, at 25° C., of solutions of the polymerDP/PT 2130 on sand (quartzite and reservoir) and analogous solutions ofthe MCAT polymer. The reservoir sand used has the following composition:

-   reservoir sand 1: quartz 50%, K-feldspar 6%, plagioclase 15%,    calcite 6%, dolomite 1%, clays/micas 22%    -   reservoir sand 2: quartz 92%, K-feldspar 5%, plagioclase 2%,        clays/micas 1%

TABLE 1 Adsorption at 25° C. of solutions of the polymer DP/PT 2130 onsand (quartzite and reservoir) and of analogous solutions of the polymerMCAT. Conc. Adsorption Adsorption Temp. solution (mg/g sand) (mg/g sand)(° C.) (ppm) DP/PT 2130 MCAT Quartzite 25 1000 0.12 0.13 25 2000 — 0.32Reservoir 1 25 1000 1.01 0.7 25 2000 1.45 1.15 Reservoir 2 25 1000 0.810.87 25 2000 0.72 1.74

It can be observed that both polymers have a limited adsorption on cleansand (quartzite) and a high adsorption on both reservoir sands.

1b1—Temperature Static Adsorption Test

Following the procedure described in 1a, adsorption tests were effectedon sand at temperatures of 70° C. and 90° C., using the polymer MCAT andthe polymer of the present invention.

The results of the test are indicated in Table 2.

TABLE 2 Comparison of the adsorption of solutions of the polymer DP/PT2130 on sand (quartzite and reservoir) and analogous solutions of thepolymer MCAT. The composition of the reservoir sands is indicated in thedescription of Table 1. Conc. Adsorption Adsorption Temp. solution (mg/gsand) (mg/g sand) (° C.) (ppm) DP/PT 2130 MCAT Quartzite 70 1000 — 0.035Quartzite 90 1000 0.13 0.058 Reservoir sand 1 70 1000 1.25 0.4 70 20001.93 0.8 Reservoir sand 1 90 1000 0.86 0.64 90 2000 1.82 1.71 Reservoirsand 2 90 1000 0.77 0.85 90 2000 1.4 1.76

It can be observed that both polymers have high adsorptions on thereservoir sands (compare with the data of Table 1), a necessary but notsufficient condition for the success of the RPM treatment.

For successful treatment, in fact, the thermal stability of the polymermust also be considered, in particular of the active cationic group, atthe desired temperature.

1b2—Evaluation of the Thermal Stability by Means of NMR Analysis

The thermal stability of the product was evaluated by means of NMRanalysis carried out on aqueous solutions of the polymers DP/PT 2130 andMCAT at different temperatures, and in particular the concentration ofactive cationic groups present at the different temperatures wasdetermined.

Table 3 provides a comparison between the thermal stability of thepolymer MCAT (in terms of percentage of cationic groups hydrolyzed atthe test temperature) and the polymer DP/PT 2130 of the presentinvention.

TABLE 3 Comparison between the thermal stability of the solution of thepolymer MCAT and of the solution of the polymer DP/PT 2130 of thepresent invention after 21 days (via NMR analysis) MCAT DP/PT 2130 Temp.Time % of cationic % of cationic (° C.) (weeks) groups hydrolyzed groupshydrolyzed 48 3 58 n.d. 70 3 >99 n.d. 90 3 n.d. 0 n.d. = not detected

A significant degradation of the active cationic groups of the polymerMCAT can already be observed at 70° C.

The polymer of the present invention, DP/PT 2130, is, on the other hand,thermally stable also at a temperature of 90° C.

1-c—Test in a Porous Medium Using the Polymer MCAT

After verifying the adsorption of the polymer on-rock, the efficacy ofthe polymer MCAT was evaluated in selectively reducing permeability towater by means of a test in a porous medium. Two tests were effected ina porous medium at two different temperatures: 48 and 70° C.

The sandpack was prepared using about 40 grams of sand, so as to obtaina core length equal to about 5 cm to which 2 cm of gravel having 20–40mesh, are added, one at the head and one at the tail, held by two70-mesh metallic nets. The diameter of the sandpack is equal to 1″.

Once the sandpack has been assembled in the Hassler steel cell, aboundary pressure of 20 bars is established to avoid the bypassing ofthe fluids between the VITON tube (which contains the core) and theporous medium. The following procedure is adopted:

-   -   Saturation under vacuum of the sandpack with brine (2% KCl) and        subsequent determination of the porosity and absolute        permeability at room temperature and at the temperature of        interest.    -   Flush of the brine with gas (nitrogen previously humidified) or        oil (crude field oil): determination of the initial permeability        relating to the gas (K_(in) gas) or crude field gas (K_(in)        crude field oil) and the corresponding saturation in water.    -   Flush of the gas (or crude field oil) with brine: determination        of the initial permeability relating to the brine (K_(in) brine)        and the corresponding saturation in gas (or crude field oil).    -   Injection of the polymeric solution of MCAT (1500 ppm)        previously filtered and degassed (from 10 to 12 pore volumes) at        a constant flow-rate. During the flush the pressure values are        collected together with the outgoing fractions to determine the        quantity of polymer adsorbed.    -   Shut-in of 24 hours.    -   Flush of the polymer with brine (2% KCl) at a constant flow-rate        (about 1 PV/h). During the flushing the pressure vales are        recorded and the outgoing fractions collected.    -   Determination of the permeability to brine after the treatment        with the polymer (K_(fin)brine).    -   Determination of the permeability to gas or oil (crude field        oil) after the treatment with the polymer (K_(fin) gas, K_(fin)        crude field oil) and of the saturation in brine.

The results of the tests are summarized in Table 4.

TABLE 4 Results of the test in a porous medium with the polymer MCAT(1500 ppm). The reduction in permeability to water was calculated afterinjecting from 600 to 900 pore volumes (PV) of brine. The reservoir sandused has the following composition: reservoir sand 3: quartz 49%,plagioclase 17%, calcite 21%, clays/micas 4%. Reduction Reduction brinegas Temp. K initial brine permeability permeability Sand (° C.) (mD) (%)(%) Reservoir 3 48 78 77 20 Reservoir 3 70 122 22 —

It can be observed that the polymer MCAT is effective as permeabilitymodifier relating to a temperature of about 50° C. At 70° C. thereduction in permeability to brine is significantly reduced with respectto what is observed at lower temperatures (22% against 77%). This is inaccordance with the data of the static adsorption tests and with the NMRanalyses carried out on the solutions, which showed a considerabledegradation of the polymer MCAT at 70° C. with an almost completedetachment of the active cationic groups. The cationic group isessential for obtaining a good adsorption and consequently a goodreduction in the permeability to brine.

Example 2 Performances of the Polymer DP/PT 2130 of the PresentInvention

Once the thermal stability of the polymer DP/PT 2130 has been defined,whose solutions proved to be stable at temperatures equal to 90° C.,with good performances in terms of sand adsorption, the performances ofthe product were evaluated by means of tests in a porous medium, inwhich the reduction in permeability to brine and the effect onpermeability to hydrocarbons (oil), were evaluated.

2-a—Tests in a Porous Medium

In the tests in a porous medium, carried out with the purpose ofevaluating the efficacy of the polymer DP/PT 2130 in reducingpermeability to brine, the procedure described in Example 1-c wasadopted. Also in this case, a polymeric solution (in brine KCl 2%) of1500 ppm, was used. The following tests were carried out:

-   -   test in a porous medium on sandpack (reservoir sand 2) at 90°        C.: determination of the reduction in permeability relating to        brine and evaluation of the effect on the permeability relating        to oil. The reservoir sand (2) used has the mineralogical        composition indicated in the description of Table 1.    -   test in a porous medium on core (clashach) at 90° C.:        determination of the reduction in permeability relating to brine        and evaluation of the effect on the permeability relating to        oil. The core (length 10 cm, diameter 2.54 cm, pore volume 9.28        cm³) has the following mineralogical composition: quartz 95%,        K-feldspar 5%.

In the tests in the porous medium carried out with the brine-oilbiphasic system, a crude field oil was used.

The results of the test are indicated in Table 5.

TABLE 5 Tests in a porous medium effected with the polymer DP/PT 2130. Atypical crude field oil was used in all the tests. Concentr. Initialpermeabil. Reduction Reduction Temperature DP/PT 2130 brine permeabil.permeabil. oil Core (° C.) (ppm) (mD) brine (%) (%) Clashach 90 1500 47448 5 Sandpack 1* 90 3000 288 50 5 Sandpack 2* 90 5000 154 70 9*reservoir sand 2 (see description of Table 1)

It can be observed that, unlike the polymer MCAT whose performances wereseriously jeopardized at high temperatures due to the degradation of theactive cationic groups, the polymer of the present invention providesexcellent performances, in terms of selective reduction in permeabilityto water also at high temperatures. These properties make the polymersuitable for RPM treatment in wells with problems relating to waterproduction and with formation temperatures of up to 90° C.

1. A process for reducing the production of water in an oil well,comprising: injecting into a formation around the well an aqueoussolution of one or more polymers of formula (I):

wherein n is from 0.40 to 0.70; m is from 0.15 to 0.65; p is from 0.02to 0.20; n+m+p =1; X₁ is selected from the group consisting of H andCH₃; R₁, R₂, may be the same or different C₁₋₁₀ monofunctionalhydrocarbyl groups.
 2. The process according to claim 1, wherein n isfrom 0.5 to 0.65, m is from 0.3 to 0.5, and p is from 0.5 to 0.10. 3.The process according to claim 1, wherein R₁, R₂, may be the same ordifferent C₁₋₃ monofunctional alkyl radicals.
 4. The process accordingto claim 3, wherein R₁═R₂═CH₃.
 5. The process according to claim 1,wherein the polymer of formula (I) has a molecular weight of from 1.5 to12 million.
 6. The process according to claim 1, wherein theconcentration of the polymer of formula (I) in the aqueous solution isfrom 300 to 10000 ppm.
 7. The process according to claim 6, wherein theconcentration of the polymer of formula (I) in the aqueous solution isfrom 500 to 4000 ppm.
 8. The process according to claim 1, wherein thepolymer of formula (I) n=0.65, m=0.30, p=0.05, X₁═H, and R₁═R₂═CH₃. 9.The process according to claim 1, further comprising: first preflushingthe formation.
 10. The process according to claim 9, wherein thepreflushing is carried out by injecting an aqueous solution containing asurface-active agent into the formation.
 11. The process according toclaim 1, further comprising: overflushing after the injecting.
 12. Theprocess according to claim 11, wherein the overflushing includesinjecting at least one of a brine, a gas, and an oil, in the formation.13. The process of claim 1, wherein the aqueous solution has a viscosityof 1.5 to 10 cP.
 14. The process of claim 1, further comprising: afterthe injecting, closing the well to adsorb the polymer in a rock matrix.15. The process of claim 1, wherein the temperature of the formation isup to 90° C.
 16. The process of claim 1, wherein the aqueous solutioncomprises a terpolymer comprising a copolymerized units of acrylamide,N-vinylpyrrolidone, and diallyldimethylammoniumchloride.
 17. The processof claim 16, wherein the polymer has a molecular weigh of about 5million.
 18. The process of claim 1, further comprising: before theinjecting, preflushing the well with an aqueous solution containing asurface active agent; after the injecting, overfiushing the well with atleast one of a brine, a gas and an oil; and then closing the well toadsorb the polymer on the formation.
 19. The process of claim 1, whereinthe formation contains siliceous sand.
 20. The process of claim 1,wherein the aqueous solution is injected as rapidly as possible at apressure that is not higher than the fracture pressure of the formation.